A sizeable opportunity exists for increasing production and reserves from a horizontal wellbore. To maximize the production and reserves, particularly oil and gas, from a horizontal wellbore and artificial lift system, the system should be designed to be, amongst other things, solids and debris tolerant:
The curved section of a horizontal wellbore is often referred to as the “heal” or “bend” or “build” section of a wellbore where, generally, the wellbore angle/inclination increases from 0 to 90 degrees. Convention sucker rod pumping systems are operationally challenged when the downhole pump component is positioned at an inclination.
All of these challenges result in undesirable higher maintenance frequencies and higher operating costs. To resolve these challenges, most horizontal wells have sucker rod pumps positioned or landed at wellbore inclination angles less than 20 degrees. Landing a pump higher up a wellbore in the minimal inclination section (or in the vertical section) means the pump will not be at the lowermost point or depth in a horizontal well (i.e., the reservoir or horizontal wellbore depth).
For reservoir fluids to inflow into a wellbore, a pressure differential from the reservoir pressure to the pressure inside wellbore must be created. When the pressure in a wellbore is less than the reservoir pressure, reservoir fluids will inflow into the wellbore and this is commonly described as the “draw down”. The greater the pressure differential between the reservoir pressure and the wellbore pressure, the greater the rate reservoir fluids will inflow into the wellbore. Equation 1 following describes this differential:Draw Down=Reservoir Pressure−Wellbore Pressure
The consequence to the production performance of a well with a pump landed higher up a wellbore is that the differential pressure between the reservoir pressure and the wellbore pressure becomes limited by the depth at which the pump is landed. The wellbore will not able to be drawn down to a minimum pressure, as an accumulation of liquid between the pump suction and the lowermost point in a horizontal wellbore imposes a hydrostatic pressure.
Any amount of vertical fluid level in a wellbore means a well is not fully drawn down. Industry often refers to a wellbore that has no fluid level above the reservoir as being “pumped off”. The higher a fluid level is in a wellbore above the reservoir depth, the greater the hydrostatic pressure of that fluid column and therefore less drawdown. The lesser the drawdown, the lower the production rate and reserves recovery. A wellbore not fully drawn down will encounter the minimum economic production rate earlier in time.
At surface, any amount of back pressure imposed to the well will also negatively impact production by reducing the drawdown. Imposing of surface backpressure is caused by surface production handling equipment (separation systems, recovery and handling of natural gas production associated with the oil production, etc.) and frictional pressure losses in a length of pipeline to the nearest battery/facility. At the sucker rod pump depth, gas and liquid are usually separated. The liquid is pumped to surface by the sucker rod pump and the gas are allowed to naturally migrate up the tubing annulus to surface.
A sucker rod pumping system is not the only means or method for artificially lifting reservoir fluids from a wellbore, but these other systems also face challenges when applied to a horizontal wellbore. The challenges associated with other artificial lift systems for removing reservoir fluids from a horizontal well are as follows:                (i) Electrical Submersible Pump (ESP)—high cost, ESP's have low operating run times when positioned horizontally, ESP's have gas locking problems when positioned horizontally, high maintenance cost to service as requires major workover operation to service (pulling of tubing required);        (ii) Progressive Cavity Pumps (screw pumps)—have elastomer run-life challenges with higher API oil gravities; high maintenance cost to service as requires major workover operation to service (pulling of tubing required);        (iii) Jet and Hydraulic Pumps—high initial cost, high maintenance cost to service as requires major workover operation to service (pulling of tubing required); and        (iv) Gas Lifting entire wellbore—high costs associated with an external gas supply requirement, considerable surface equipment requirement, high gas injection pressures, high gas injection rates, and challenges achieving low pressures at lowermost point in a wellbore due to gas expansion friction and inability to place entire well in a mist flow regime condition, high maintenance cost to service as requires major workover operation to service (pulling of tubing required).        